Grant Agreement no.: 213824 Project Acronym: MED-CSD Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries Instrument: Coordination and Support Actions Theme: ENERGY.2007.2.5.2: Using CSP for Water Desalination WP1: Technology Review and Selection of CSP and Desalination Configurations adapted for Application in the Southern and Eastern Mediterranean Region Final Report June 2009 Project coordinator: Dr.Houda Ben Jannet Allal Work Package 1 Leader Organisation: DLR
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Grant Agreement no.: 213824
Project Acronym: MED-CSD
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean
Partner Countries
Instrument: Coordination and Support Actions
Theme: ENERGY.2007.2.5.2: Using CSP for Water Desalination
WP1: Technology Review and Selection of CSP and Desalination Configurations adapted for
Application in the Southern and Eastern Mediterranean Region
Final Report
June 2009
Project coordinator: Dr.Houda Ben Jannet Allal
Work Package 1 Leader Organisation: DLR
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
WP1: Technology Review Page 2
Authors: Franz Trieb, Massimo Moser, German Aerospace Center (DLR), Stuttgart, Germany
Jürgen Scharfe, Marie Luise Tomasek (INVEN Engineering GmbH), München, Germany
Jürgen Kern (kernenergien), Stuttgart, Germany
Thomas Nieseor, Nicolas Cottret, Observatoire Méditerranéen de l’Energie (OME), Paris,
France
Pinhas Glueckstern, Inbal David, Menahem Priel (Mekorot), Israel
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
linear Fresnel (bottom left), central receiver solar tower (top right), dish-Stirling
engine (bottom right).
Table 3-2 gives a comparison of the main features of solar thermal power
technologies. In addition to the concentrating solar power technologies described
above, the solar thermal updraft tower has been included for comparison.
SecondaryReflector
Fresnel Reflector
Absorber Tube
Sunlight
Steam at350 - 550 °C 80 - 120 bar *
Molten Salt, Air or Helium at 600 - 1200 °C1 - 20 bar *
line concentrators point concentrators
SecondaryReflector
Fresnel Reflector
Absorber Tube
Sunlight
Steam at350 - 550 °C 80 - 120 bar *
Molten Salt, Air or Helium at 600 - 1200 °C1 - 20 bar *
point concentratorsconcentrators line
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
WP1: Technology Review Page 27
Technology Parabolic Trough System Linear Fresnel System Solar Power Tower Dish Stirling Engine Solar Updraft Tower Applications Superheated steam for grid
connected power plants Saturated and superheated steam for process heat and for grid connected power plants
Saturated and superheated steam for grid connected power plants
Stand-alone, decentralized, small off-grid power systems. Clustering possible.
Large grid connected systems.
Capacity Range (MW) 10-200 5-200 10-100 0.1-1 30-200 MW Realized max. capacity of single unit (MW) 80 (250 projected) 2 (30 under construction) 10 (20 under construction) 0.025 0.05Capacity installed (MW) 480 (500 under construction) 2 (30 under construction) 10 (20 under construction) trials 0Annual Efficiency (%) 10 to 16 (18 projected) 8 to 12 (15 projected) 10 - 16 (25 projected) 16 to 29 1 to 1.5 Heat Transfer Fluid Synthetic Oil, Water/Steam
demonstratedWater / Steam Water / Steam, Air Air Air
Temperature (°C) 350-415 (550 projected) 270-400 (550 projected) 250-565 750-900 30-50Concentration Ratio (mirror aperture / absorber aperture) 50-90 35-170 600-1000 Up to 3000 no concentrationOperation mode solar or hybrid solar or hybrid solar or hybrid solar or hybrid solar onlyLand Use Factor (aperture area / land area) 0.25-0.40 0.60-0.80 0.20-0.25 0.20-0.25 1Estimated investment costs (€/kW) for SM1-SM2 3,500-6,500 2,500-4,500 4,000-6,000 6,000-10,000 (SM1 only) 4,000-8,000 Development Status Commercially proven Recently commercial Semi-commercial Prototype testing Prototype testing Storage Options Molten Salt, Concrete, Phase
Change MaterialConcrete for pre-heating and superheating, Phase Change Material for Evaporation
Molten Salt, Concrete, Phase Change Material
No storage available Storage possible
Reliability Long-Term Proven Recently Proven Recently Proven Demonstrated Not yet demonstratedMaterial Demand of Solar Field (kg/m²) 120-140 30-130 100-250 300-400 90-110
Long-term proven reliability and durability
Simple structure and easy field construction
High temperature allows high efficiency of power cycle
High temperature allows high efficiency of power cycle
Easily Available Materials
Storage options for oil-cooled trough available
Tolerance for slight slopes Tolerates non-flat sites Independent from land slope
Direct steam generation proven Possibility of powering gas turbines and combined cycles
High Modularity
Limited temperature of heat transfer fluid hampering efficiency and effectiveness
Storage for direct steam gene-rating systems (phase change material) in very early stage
High maintenance and equipment costs
Not commercially proven Not commercially proven
Complex structure, high precision required during field construction
High complexity compared to stand-alone PV
Tower height approx. 1000 m
Requires flat land area High land requirements Very high material demandRequires large flat land area
Advantages
Disadvantages
Table 3-2: Comparison of solar thermal power technologies (SM1-SM2 explained in text)
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
WP1: Technology Review Page 28
3.2 HEAT STORAGE OPTIONS FOR CONCENTRATING SOLAR POWER
3.2.1 Principles of Heat Storage
Heat storage is one of the most distinguishing features of CSP with respect to other
renewable energy technologies like wind power or photovoltaics. It allows production
of electricity on demand just like from fuel oil or natural gas, but based on fluctuating
solar energy resources (Figure 3-7). This is a very important option to increase the
revenues from power sales, as off-peak solar energy from the morning hours can be
shifted to the evening on-peak electricity demand, often achieving sales prices by a
factor of two or three higher. In the case of seawater desalination, the continuous
operation of the desalination plants - either by reverse osmosis or thermal
desalination - is crucial in order to avoid scaling and bio-fouling which would occur
immediately if plants would be left idle.
Figure 3-7: The use of thermal energy storage in a CSP plant to shift electricity output from
morning off-peak to evening on-peak demand (Dracker and Riffelmann 2008).
Therefore, heat storage was always an important issue during CSP development,
and in the meantime, significant experience has been accumulated world wide
(Figure 3-8). Direct storage of synthetic oil heat transfer fluid and molten salt as
storage media have been investigated and used in industry since the 1980ies and
thus can be considered commercial. While the use of HTF is considered too
expensive as storage medium, molten salt has been developed to maturity and is
currently applied in several CSP plants in Spain. New storage concepts based on
concrete and phase change material are presently under development.
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
WP1: Technology Review Page 29
1980 1990 2000 2010
Solar TwoMolten Salt565°CSEGS I
Mineral Oil307°C
Real DissPCM + Concrete500°C
DistorPCM225°C
100 MWh
1000 MWh
10 MWh
1 MWh
100 kWh
10 kWh
Andasol1Molten Salt390°C
Andasol2Molten Salt390°C
WESPEConcrete390°C
PROSPERPCM145°C
PS10Steam accumulator245°C
PS20Steam accumulator245°C
ThemisMolten salt450°C
ThermoclineMolten salt/filler390°C
Solar OneOil/Rock/Sand305°C
research
commercial
start of operation
The
rmal
Sto
rage
Cap
acity
CESA-1Molten salt340°C
TSAPebble-bed700°C
STJCeramics700°C
Figure 3-8: Experience using energy storage systems in CSP plants (Zunft 2008)
Temperature
Energy
heat transfer fluid
sensible heat storage
water / steampower cycle
preheating
evaporationsuperheating
heating up / cooling down
heating up / cooling down
Temperature
Energy
heat transfer fluid
sensible heat storage
water / steampower cycle
preheating
evaporationsuperheating
heating up / cooling down
heating up / cooling down
preheating
evaporationsuperheating
preheatingevaporation
superheating
water / steampower cycle
PCM storage
direct steamfrom CSP
melting / solidf.
solid
liquid
Temperature
Energy
preheating
evaporationsuperheating
preheatingevaporation
superheating
water / steampower cycle
PCM storage
direct steamfrom CSP
melting / solidf.
solid
liquid
Temperature
Energy
Temperature
Energy
heat transfer fluid
sensible heat storage
water / steampower cycle
preheating
evaporationsuperheating
heating up / cooling down
heating up / cooling down
Temperature
Energy
heat transfer fluid
sensible heat storage
water / steampower cycle
preheating
evaporationsuperheating
heating up / cooling down
heating up / cooling down
preheating
evaporationsuperheating
preheatingevaporation
superheating
water / steampower cycle
PCM storage
direct steamfrom CSP
melting / solidf.
solid
liquid
Temperature
Energy
preheating
evaporationsuperheating
preheatingevaporation
superheating
water / steampower cycle
PCM storage
direct steamfrom CSP
melting / solidf.
solid
liquid
Temperature
Energy
Figure 3-9: Temperature of heat transfer fluid and sensible heat storage vs. steam
temperature of a Rankine cycle (left) and temperature of direct steam generating
CSP and PCM vs. steam temperature of Rankine cycle (right).
The main reason for developing phase change materials for heat storage is the fact
that most of the energy transfer to the water steam cycle of a power plant takes place
at constant temperature during the evaporation phase from water to steam (Figure
3-9). Using synthetic oil heat transfer fluid and sensible heat storage is on one side
limited by the upper allowable temperature of the HTF which is about 390 °C and on
the other side by the required steam conditions of the power plant, which are best if
pressure and temperature are high, ideally above 500°C and 120 bar. Using HTF
only 370 °C at 100 bar pressure can be achieved, limiting the efficiency of the power
cycle to values below state of the art. Moreover, the limited temperature difference
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
WP1: Technology Review Page 30
between the cold and hot end also limits storage capacity and increases the amount
of material required.
Direct steam generating concentrating solar collector systems can easily achieve the
temperatures required by steam power cycles, but there is no suitable sensible heat
storage technology available for the evaporation phase which allows for a significant
heat transfer at constant temperature. Therefore, phase change materials are
applied, using the melting heat of the material for energy storage (Laing et al. 2009).
As PCM materials are usually rather expensive, it was proposed to use sensible heat
storage for the pre-heating and superheating segments of a steam power cycle and
PCM only for the evaporation segment. Such systems are presently under
development (Laing et al. 2009).
from solar field
to power block
from power block
to solar field
concrete storage module PCM storage
module
concrete storage module
A B
C
D
A feed water inlet / outletB liquid water
C saturated steamD live steam inlet / outlet
preheating
evaporation/ condensation
superheating
from solar field
to power block
from power block
to solar field
concrete storage module PCM storage
module
concrete storage module
AA BB
CC
DD
A feed water inlet / outletB liquid water
C saturated steamD live steam inlet / outlet
preheating
evaporation/ condensation
superheating
Figure 3-10: Concept of using a combined concrete/phase change material storage systems
for direct steam generating solar power plants (Zunft 2008, Laing 2009)
In the following we will explain different heat storage options for CSP and show the
experience gained within concrete projects in Europe.
3.2.2 Sensible Heat Two-Tank Molten Salt Storage
Molten salt is a medium often used for industrial thermal energy storage. It is
relatively low-cost, non-flammable and non-toxic. The most common molten salt is a
binary mixture of 60% sodium nitrate (NaNO3) and 40% potassium nitrate (KNO3).
During operation, it is maintained at 290°C in the cold storage tank, and can be
heated up to 565°C. Two-tank storage systems are very efficient, with about 1-2%
EC-FP7 Project
Grant Agreement no.: 213824
Combined Solar Power and Desalination Plants: Techno-Economic Potential in Mediterranean Partner Countries (MED-CSD)
WP1: Technology Review Page 31
loss over a one day storage period. Because the molten salt mixture freezes at
temperatures about 230°C (depending upon the salt's composition) care must be
taken to prevent it from freezing at night, especially in any of the piping system.
Heat exchangers are used to transfer the heat from the solar field heat transfer fluid
to the hot tank. During discharge, the heat transfer fluid is circulated through the
same heat exchangers to extract the heat from the storage and transfer it to the solar
power plant steam generator. The investment cost of a two-tank molten salt system
is about 40-60 €/kWh.
Figure 3-11: Sketch of molten salt tanks at ANDASOL 1 (ACS Cobra)
Figure 3-12: Molten salt storage tanks at ANDASOL 1 with 1010 MWh storage capacity
during construction in December 2007 (ACS Cobra)
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WP1: Technology Review Page 32
3.2.3 Sensible Heat Concrete Storage
A sensible heat storage system using concrete as storage material has been
developed by Ed. Züblin AG and German Aerospace Center DLR. A major focus was
the cost reduction of the heat exchanger and the high temperature concrete storage
material. For live cycle tests and further improvements a 20 m³ solid media storage
test module was built and cycled by an electrically heated thermal oil loop. The solid
media storage test module has successfully accumulated about one year of
operation in the temperature range between 300 °C and 400 °C. Investment is at
present about 30-40 €/kWh with a medium term cost target of 20 €/kWh.
Figure 3-13: Sketch of a concrete storage with view on the tube bundle that serves as heat
exchanger between the concrete and the heat transfer fluid (Laing et al. 2008)
Figure 3-14: Set-up of a 1100 MWh concrete storage from 252 basic storage modules for a
50 MW concentrating solar power plant (Laing et al. 2008)
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WP1: Technology Review Page 33
3.2.4 Latent Heat Phase Change Material Storage
A major technical problem for the implementation of high-temperature latent heat
storage systems is the insufficient thermal conductivity of the available phase change
materials of around 0.5 W/(mK). During the discharge process, the energy released
by solidification of the storage material must be transported from the solid-liquid
interface through the growing solid layer to the heat exchanger surface (Figure 3-15).
Unfortunately, the thermal conductivity of the solid PCM is rather low.
Figure 3-15: Solidification of PCM around heat exchanger tube during discharging (left) and
finned tube design (right) developed to overcome the reduced heat transport
through the solidified material (Laing et al. 2009)
Fins attached vertically to the heat exchanger tubes can enhance the heat transfer
within the storage material. Fins can be made of graphite foil, aluminium or steel.
High temperature latent heat storage with high capacity factors was demonstrated at
different temperature levels. The sandwich concept using fins made either from
graphite or aluminium was proven as the best option to realize cost-effective latent
heat energy storage. The application of graphite is preferred for applications up 250
°C; at higher temperatures aluminium fins are used.
Feasibility was proven by three prototypes using graphite and by a further storage
unit using aluminium fins. The prototype with aluminium fins filled with sodium nitrate
was operated for more than 4000 h without degradation of power. PCM test storage
facility with a capacity of approx. 700 kWh is currently being fabricated. Other
activities aim at the thermo-economic optimization of the storage concept; further
storage systems using the sandwich concept are under development (Laing et al.
2009). A cost of 40-50 €/kWh is expected for large scale storage systems.
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WP1: Technology Review Page 34
Figure 3-16: Phase change material demonstration plant with 200 kWh storage capacity at
German Aerospace Center (Laing 2008)
3.2.5 Steam Accumulator
Storage of sensible heat in pressurized liquid water (Ruths Storage) is used in
several industrial applications as short term (typically 0.5 to 2 h) steam buffer. The
storage is charged by condensing high temperature steam and thus raising the
temperature of the water volume contained. During discharge, the pressure within the
hot water vessel is decreased. Part of the water evaporates and can be withdrawn as
saturated steam. The thermal capacity of the storage is proportional to the heat
capacity of the contained water and to the temperature difference allowable for the
steam process between charging and discharging. Investment of the pressurized
steam vessel is rather high at about 180 €/kWh.
Figure 3-17: Principle of steam accumulator heat storage (Laing 2008)
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Figure 3-18: Steam accumulator with 1-hour storage capacity at PS-10 concentrating solar
power station (Abengoa Solar)
3.2.6 Hot Water Storage
A stratified hot water tank at normal ambient pressure can in principle be used to
store low temperature heat below 100 °C required e.g. for a multi-effect thermal
desalination process. In a stratified tank during discharge, cold water is returned to
the bottom and hot water is taken from the top of the tank. The different temperature
layers are stabilised by gravity.
Figure 3-19: Solar flat plate collectors for water heating (left) and seasonal hot water storage
(right) with 6,000 m³ volume at Olympic Park, Munich (Kuckelhorn et al. 2002)
Large scale storage systems up to 20,000 m³ capacity have been developed in
Germany for seasonal storage of low temperature heat from flat plate solar collectors
for room heating, accumulating solar energy in the summer and releasing heat to the
space heating system in winter. The storage temperature is typically cycled between
a maximum of 95°C and a lower temperature of 50°C. Lower storage temperatures
can be achieved if heat pumps are applied. The stored energy is proportional to the
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WP1: Technology Review Page 36
heat capacity of the water stored and to the temperature difference achieved during
cycling. Investment cost is between 50 and 150 €/m³. For a temperature difference of
30 °C, this would be equivalent to a cost of storage capacity of about 2-5 €/kWh.
Figure 3-20: Sketch of a solar/fuel hybrid district heating system with low temperature
seasonal energy storage (Mangold and Müller-Steinhagen 2002)
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Technology Molten Salt Concrete Phase Change Material Water/Steam Hot WaterCapacity Range (MWh) 500-> 3,000 1->3,000 1->3,000 1-200 1-3,000Realized max. capacity of single unit (MWh)
1,000 2 0.7 50 1,000 (not for CSP)
Realized max. capacity of single unit (full load hours)
7.7 not yet applied to CSP plants not yet applied to CSP plants 1.0 not yet applied to CSP plants
Capacity installed (MWh) 1,000 3 0.7 50 20,000 (not for CSP)Annual Efficiency (%) 0.98 0.98 0.98 0.9 0.98Heat Transfer Fluid synthetic oil synthetic oil, water/steam water / steam water / steam waterTemperature Range (°C) 290-390 200-500 up to 350 up to 550 50-95Investment Cost (€/kWh) 40-60 30-40 (20 projected) 40-50 projected 180 2-5Advantages high storage capacity at
relatively low costwell suited for synthetic oil heat transfer fluid
latent heat storage allows for constant temperature at heat transfer
latent heat storage allows for constant temperature at heat transfer
very low cost storage for process heat below 100°C
experience in industrial applications
easily available material low material requirements experience in industrial applications
experience in industrial applications
well suited for synthetic oil heat transfer fluid
well suited for pre-heating and superheating in direct steam generating collectors
well suited for evaporation/condensation process in direct steam generating collectors
well suited for evaporation/condensation process in direct steam generating collectors
Disadvantages sensible heat storage requires temperature drop at heat transfer
not suited for evaporation/condensation process in direct steam generating collectors
not suited for pre-heating and superheating in direct steam generating collectors
not suitable for pre-heating and superheating
sensible heat storage requires temperature drop at heat transfer
molten salt freezes at 230°C recent development very early stage of development
not applicable to power generation
Table 3-3: Comparison of the principal features of solar thermal storage technologies
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3.3 PARABOLIC TROUGH COLLECTORS FOR STEAM CYCLE POWER PLANTS (20 - 200 MW)
3.3.1 Parabolic Trough Collector with Synthetic Heat Transfer Fluid
As shown in Figure 3-21 and Figure 3-23, some line focusing systems use parabolic
trough mirrors and specially coated steel absorber tubes to convert sunlight into
useful heat. The troughs are normally designed to track the sun along one axis,
predominantly north-south. To generate electricity, a fluid flowing through the
absorber tube – usually synthetic oil or water/steam – transfers the heat to a
conventional steam turbine power cycle. Concentrating the sunlight by about 70 - 100
times, typical operating temperatures are in the range of 350 to 550 °C. Plants of 200
MW rated power and more can be built by this technology. Hybrid operation with all
kinds of fossil or renewable fuels is possible (Müller-Steinhagen & Trieb, 2004). In
order to increase the number of solar operating hours beyond the times when the sun
shines, the collector field can be designed to provide, under standard conditions,
more energy than the turbine can accept. This surplus energy is used to charge a
heat storage, which can provide the required energy input to the turbine system
during periods of insufficient solar radiation (Tamme et al., 2004).
Figure 3-21: Absorber tube with selective coating and evacuated glass envelope by Schott
Solar AG, Germany (left) and parabolic trough collector assembly at the
Plataforma Solar de Almeria, Spain (right).
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Figure 3-22: Impressions of the Californian Solar Electricity Generating Systems
The experience of parabolic trough steam cycles dates back to 1985, when the first
of a series of 9 solar electricity generating systems (SEGS) was commissioned in
California, with a rated capacity between 14 MW (SEGS I) and 80 MW (SEGS (IX
commissioned in 1991). The plants have been run successfully since then producing
more than 15,000 GWh of solar electricity up to now.
In Europe a first plant of this type with 50 MW rated power using synthetic oil as heat
transfer fluid and a molten salt tank system with 7 full load hours storage capacity
has been commissioned in April 2009 in the Spanish Sierra Nevada near Guadix. On
July 20th 2006, construction started for the 50 MWel parabolic trough plant
ANDASOL 1, which will be followed by identical plants ANDASOL 2 & 3 in the next
couple of years. Its collector area of over 510,000 square meters makes Andasol 1
the world’s largest solar power plant. It will generate approximately 179 GWh of
electricity per year to supply some 200,000 people with solar electricity after a
construction time of two years. Another 64 MW parabolic trough plant was
commissioned in Nevada in summer 2007. All in all, there is a world-wide capacity of
over 2000 MW to be commissioned within the coming 5 years period. The investment
cost amounted to 310 M€ (Schott 2006).
Heat storage consists of two large tanks, each containing a molten nitrate salt
mixture as storage medium with the necessary heat capacity for several hours of full
load operation of the turbine. Heat is transferred from or to the heat transfer fluid of
the collector via a heat exchanger. The liquid molten salt is pumped through this heat
exchanger from the cold tank to the hot tank during charging and vice versa during
discharging periods (Figure 3-23 and Figure 3-24).
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Figure 3-23: Simplified sketch and basic design parameters of the ANDASOL 1 plant
(EC 2007)
Figure 3-24: Andasol-1 parabolic trough solar field, molten salt storage tanks and power
station during construction in December 2007 (Source: ACS Cobra S.A., Spain).
3.3.2 Parabolic Trough for Direct Steam Generation
The present parabolic trough plant design uses a synthetic oil to transfer energy to
the steam generator of the power plant cycle. Direct solar steam generation in the
absorber tubes of parabolic trough collectors is a promising option for improving the
economy of solar thermal power plants (Eck & Steinmann, 2005), since all oil-related
components become obsolete and steam temperature (and hence efficiency) can be
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increased. Steam temperatures up to 400 °C at 100 bar pressure have been reached
within the framework of a European projects DISS and INDITEP undertaken over
6000 operating hours at the Plataforma Solar de Almería, Spain. The test loop with
700 m length and an aperture of 5.70 m has been custom designed and constructed
for the purpose of demonstrating safe operation and controllability under constant
and transient operating conditions.
V18
G
INDITEP component nomenclature
T
BT
CT
FWT
FT
MS 7FS
D
MS 1
MS 2
MS 3
MS 4
MS 5
MS 6
C
BT = buffer tankC = condenserCT = condense water tankD = deaeratorFS = final separatorFT = flash tankFWT = feed water tankAB = auxiliary boiler
G = generatorMS 1 . . MS 7 = middle separatorsP1 = feed water pumpP2 = recirculation pumpP3 = condense water pumpP4 = auxiliary boiler water pumpT = turbineV 1 ..V 53 = valves
P2
P1
V1 V2
V3
V4
V5
V6
V7
V8
V9
V10
V12
V11
V13
V14V15
V16
V17
V19
V20
V22
V23
V24
V26
V27
V28
V29
V30
V31
V32
V33
V34
V35
V36
V37
V38
V39
V40
V41
V42
V25
V21
P3
V49
V48
V47
V46
V45
V44
V43
V52
AB
V51
V50P4
V53
Figure 3-25: Schematic diagram of a direct steam generating solar collector field for a 5 MW
pre-commercial solar thermal power plant designed by DLR (INDITEP, 2004).
3.4 LINEAR FRESNEL COLLECTORS FOR STEAM CYCLE POWER PLANTS (5 - 200 MW)
Linear Fresnel systems have recently been developed by several companies with the
goal to achieve a more simple design and lower cost than the parabolic trough. The
first prototypes realised up to now are promising, and first power plants are presently
in the design phase. It is expected that this technology will be commercially available
around the year 2010. In a Fresnel system, the parabolic shape of the trough is split
into several smaller, relatively flat segments. These are put on a horizontal rag and
connected at different angles to a rod-bar that moves them simultaneously to track
the sun during the day. Due to this arrangement, the absorber tube can be fixed
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above the mirrors in the centre of the solar field, and does not have to be moved
together with the mirror during sun-tracking.
Figure 3-26: Animation of a Linear Fresnel Collector Field by FhG/ISE
While parabolic troughs are fixed on central pylons that must be very sturdy and
heavy in order to cope with the resulting central forces, the Fresnel structure allows
for a very light design, with the forces absorbed by the four corners of the total
structure. Large screws instead of pylons are literarily screwed into the ground and
hold the lateral bars of the Fresnel structure.
Compared to the existing parabolic trough, some linear Fresnel collector systems
show a weight reduction per unit area of about 75%. This reflects not only a lower
cost, but also leads to a lower emission of pollutants during construction. On the
other hand, the simple optical design of the Fresnel system leads to a lower optical
efficiency of the collector field, requiring about 33-38% more mirror aperture area for
the same solar energy yield compared to the parabolic trough.
In terms of integration of the solar field to its environment, Fresnel systems have
considerable advantages over parabolic troughs. Land use is much better, as the
distances between mirrors are much smaller. The collector aperture area covers
between 65 % and 90 % of the required land, while for a parabolic trough, only 33 %
of the land is covered by mirrors, because the distances between the single
parabolic-trough-rows required to avoid mutual shading are considerable. Land use
efficiency of a linear Fresnel can thus be about 3 times higher than that of a parabolic
trough. Considering the lower optical efficiency of the Fresnel (2/3 of that of a
parabolic trough), this leads to a roughly two times better solar energy yield per
square meter of land of the Fresnel system when compared to a parabolic trough.
This fact may not be of much importance in remote desert areas were flat, otherwise
unused land is not scarce, but it may be of importance when integrating CSP to
industrial or tourist facilities, or placing CSP near the coast and close to urban
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centres of demand. The flat structure of the Fresnel segments can be easily
integrated to industrial or agricultural uses. In the hot desert, the shade provided by
the Fresnel segments may be a valuable extra service provided by the plant. It could
cover all types of buildings, stores or parking lots protect certain crops from
excessive sunshine and reduce water consumption for irrigation.
3.4.1 Linear Fresnel Collector for Direct Generation of Superheated Steam
In July 2007 the first large scale linear Fresnel concentrating solar collector with 1500
m² collector area was inaugurated by a joint venture of Solar Power Group (SPG)
and MAN at the Plataforma Solar de Almería. The collector, erected under the frame
of the project FRESDEMO funded by the German government, has produced in a
very stable and continuous way superheated steam at a temperature of 450°C and a
pressure of 100 bar. The superheated steam was generated directly inside the
absorber tube without the use of any heat transfer fluid other than water. Electricity
was not generated yet.
In May 2008, the German Solar Power Group GmbH and the Spanish Laer S.L.
agreed upon the joint execution of a solar thermal power plant in central Spain. This
will be the first commercial solar thermal power plant in Spain based on the Fresnel
collector technology of the Solar Power Group. The planned capacity of the power
plant will be 10 MW. It will combine a solar thermal collector field with a fossil co-
firing unit as backup system. Start of construction is planned for 2009. The project is
located in Gotarrendura about 100 km northwest of Madrid, Spain.
The Fresnel-technology is a line-focussing type of concentrating solar power (CSP).
It is based on large arrays of modular Fresnel reflectors which direct the sunlight to a
stationary receiver several meters high. This receiver contains a steel absorber tube
and a so-called second stage reflector which re-directs the rays which did not directly
hit the absorber. In the absorber tube, the concentrated sunlight is converting water
to superheated steam with temperatures up to 450°C driving a turbine to produce
electricity (SPG 2009).
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Figure 3-27: Absorber tube box (left) and linear Fresnel collector assembly (right) of the
FRESDEMO project at Plataforma Solar de Almeria, Spain (Source: MAN/SPG).
3.4.2 Linear Fresnel Collector for Direct Generation of Saturated Steam
The first European linear Fresnel system for power generation was commissioned in
March 2009 near Calasparra, Spain. The Puerto Errado Plant No. 1 (PE 1) has two
collector units about 800 meters long with a total of 18,000 m² collector area
producing enough steam for a rated power capacity of 1 MW, each. The collectors
are fabricated by robots in an automated production factory in Fortuna, Spain with a
capacity of 220,000 m²/y. The automated fabrication has led to a very high optical
accuracy of the reflector panels, while the on-site erection of the modular system is
relatively simple. The regular cleaning of the collector field segments is also done
automatically by a robot. The collector field produces directly steam at 55 bar, 270 °C
which is fed into a saturated steam turbine with 1.4 MW capacity. An annual
electricity production of 2.9 GWh is expected.
Figure 3-28: Puerto Errado linear Fresnel power station with 2 MW capacity (Novatec 2009)
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Figure 3-29: Robot automatically assembling a linear Fresnel reflector element (left) and
cleaning robot in operation on the solar field (right) (Paul 2008, Novatec 2009)
Figure 3-30: Simplified sketch of a saturated steam cycle power station with linear Fresnel
collector for solar only operation (left) and with additional fossil fuel fired
superheater (right) (Novatec 2009)
The implementing companies Novatec and Prointec are planning to install another
facility PE-2 with a considerably higher capacity of 30 MW at Puerto Errado with a
turnkey investment of 120 M€ which is presently under construction, and three further
plants near Lorca.
The plants include a short term steam storage facility to compensate for cloud
transients and use air-cooled condensers which can be applied anywhere without
need for cooling water. There is a possibility of superheating the steam coming from
the solar field by a conventional fossil fuel fired superheater (Figure 3-30). For the
future, superheating of steam within the collector field to 350 °C is scheduled to be
developed within the next generation of concentrating solar collectors.
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3.5 CENTRAL RECEIVER SYSTEMS FOR STEAM CYCLE POWER PLANTS (10 - 100 MW)
3.5.1 PS10 Central Receiver for Saturated Steam Cycle Power Plant
The PS10 plant is a project funded by the European Community under the 5th
Framework Programme (1998-2002)
The 11 MW PS10 solar power plant makes use of existing and proven technologies -
as glass-metal heliostats, a saturated steam receiver, and water pressurised thermal
storage.
The PS10 has 624 heliostats; each one is a mobile 120m² curved reflective surface
mirror. The receiver is designed to produce saturated steam at 250°C from thermal
energy supplied by concentrated solar radiation. The thermal power received by the
receiver is about 55MW at full load. The system has a saturated water thermal
storage with a capacity of 20MWh. A part of the steam produced is used to load the
thermal storage system during the full load operation of the plant.
The PS10 central receiver solar tower plant was built by Abengoa Solar after several
years of research and development and began operation on March 30th, 2007. It is
located in the Spanish province of Sevilla, in Sanlúcar la Mayor, and sits on 150
acres (60 ha). It is the first solar tower in the world commercially delivering electricity.
As seen in the operating schematic the plant generates saturated pressurized steam
to run a conventional power cycle with 11 MW nominal power. The PS10 plant has
624 heliostats that are 120 m² each, which have an independent solar tracking
mechanism that directs solar radiation toward the receiver. Heliostats have to be
regularly cleaned and - when wind speed is higher than 36 km/h - they have to be set
vertically to avoid structural damages. The receiver is located in the upper section of
the tower. The receiver is a “cavity” receiver of four verticals panels that are 5.5 m
wide and 12 m tall. The panels are arranged in a semi-cylindrical configuration and
housed in a squared opening 11 m per side.
PS10 investment cost is about € 35 million. The project has been granted with some
public contributions because of its highly innovative features. In this sense, 5th
Framework Programme of European Commission has contributed through DG TREN
(Directorate General for Transport and Energy) to PS10 investment costs with a € 5
million subvention (total eligible costs were € 16.65 million). In the same way, the
regional administration through the Consejería de Innovación Ciencia y Empresa in
the Junta de Andalucía Autonomic Government has supported PS10 project with €
1.2 million.
A second plant with 20 MW capacity (PS 20) is presently under construction at the
same location.
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Figure 3-31: PS10 central receiver schematic and design parameters (Abengoa Solar, EC
2007)
Figure 3-32: PS 10 central receiver solar tower facility near Sevilla, Spain (Abengoa Solar). In the background the PS20 facility can be seen under construction
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3.5.2 The Solar Tres Central Receiver Plant Project
The main aim of the Solar Tres project is to demonstrate the technical and economic
viability of molten salt solar thermal power technologies to deliver clean, cost-
competitive bulk electricity.
Solar Tres consists of a 15 MW plant using the same central receiver approach as
PS-10, while using innovative solutions for the energy storage system. The project
total costs are about €196 million, the total eligible costs more than €15.3 million and
the EC contribution is about €5 million. The partners involved in the Solar Tres
project are GHERSA (Spain), Compagnie de Saint Gobain (France), CIEMAT
(Spain), and Siemens (Germany). The Solar Tres project takes advantage of several
technological innovations. These include:
A larger plant with a 2,480-heliostat field and 120 m2 glass metal heliostats –
the use of a large-area heliostat in the collector field greatly reducing plant
costs, mainly because fewer drive mechanisms are needed for the same
mirror area.
A 120 MW (thermal) high-thermal-efficiency cylindrical receiver system, able
to work at high flux, and lower heat losses.
A larger thermal storage system (15 hours, 647MWh, 6,250 t salts) with
insulated tank immersion heaters – this high-capacity liquid nitrate salt
storage system is efficient and low-risk, and high-temperature liquid salt at
565ºC in stationary storage drops only 1-2ºC/day. The cold salt is stored at
45ºC above its melting point (240ºC), providing a substantial margin for
design.
Figure 3-33: Sketch and basic design parameters of the Solar Tres central receiver plant
(EC 2007).
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3.5.3 The Solarturm Jülich Central Receiver Project in Germany
A central receiver demonstration plant is scheduled to be commissioned by mid 2009
in Jülich, Germany. The plant was developed by Solarinstitut Jülich and Kraftanlagen
München (KAM) and has a heliostat field with roughly 20,000 m² area. The core
element of the plant is an innovative open volumetric (porous) high temperature
receiver (HiTRec) developed by DLR with 22 m² surface in 55 m height on the central
tower, heating up ambient air that is sucked into the receiver to about 700 °C. By
means of a heat exchanger, the hot air is used to produce superheated steam at 485
°C, 27 bar for a steam cycle power plant with 1.5 MW power capacity. The plant also
has a ceramic packed bed as heat storage facility for about 1 hour operation to
overcome cloud transients. The plant is operated by Stadtwerke Jülich GmbH. The
overall investment cost of the plant is about 22 M€.
Figure 3-34: Heliostat field in front of the 1.5 MW central receiver power tower in Jülich,
Germany (left) and sketch of the plant configuration (right) (STJ 2009)
3.6 CENTRAL RECEIVER SYSTEMS FOR GAS TURBINES AND COMBINED CYCLE POWER PLANTS (5 - 100 MW)
Solar towers use a large field of two-axis tracking mirrors (heliostats) that reflect the
sunlight to a central receiver on top of a tower, where the concentrated solar energy
is converted to high temperature heat. The typical optical concentration factor ranges
from 200 to 1000, and plant sizes of 5 to 150 MW are feasible. The high solar fluxes
impinging on the receiver (average values between 300 and 1000 kW/m²) allow
working at high temperatures over 1000 ºC and to integrate thermal energy into
steam cycles as well as into gas turbines and combined cycles (Figure 3-36). These
systems have the additional advantages that they can also be operated with natural
gas during start-up and with a high fossil-to-electric efficiency when solar radiation is
insufficient. Hence, no backup capacities of fossil fuel plants are required and high
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capacity factors are provided all year round. In addition, the consumption of cooling
water is reduced significantly compared to steam cycle systems.
The high temperature for gas turbine operation and the heat transfer using air require
a different receiver concept than the absorber tubes used in linear concentrating
systems. Volumetric receivers do not absorb the concentrated solar radiation on an
outer tube surface, but within the volume of a porous body. Air can be used as heat
transfer medium which is flowing through that porous material, taking away the heat
directly from the surface where it has been absorbed. Due to the excellent heat-
transfer characteristics, only a small temperature gradient between the absorber
material and the air exists, and thermal losses are reduced. Also, the heat flux
density can be much higher than in gas cooled tube receivers (SOLGATE 2005).
The porous material can be a wire mesh for temperatures up to 800 °C or ceramic
material for even higher temperatures (Fend et al., 2004). There are two principal
designs of volumetric receivers: the open or atmospheric volumetric receiver uses
ambient air sucked into the receiver from outside the tower. The heated air flows
through the steam generator of a Rankine cycle. The second concept is the closed or
pressurised volumetric receiver that uses pressurised air in a receiver closed by a
quartz window (Figure 3-35).
This system can heat pressurised air coming from the compressor of a gas turbine
power cycle. A first pilot system (Solgate) has been installed and tested on the
Plataforma Solar de Almería in Spain and the following targets have been reached:
receiver outlet temperature 1050 °C with pressures up to 15 bar,
90 % secondary concentrator efficiency,
external cooling of window to maintain glass temperatures below 800 °C, with negligible thermal losses,
demonstration of controlled system operation, 230 kW electric power output achieved.
Figure 3-35: Pressurised air heated by solar energy using a volumetric receiver
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Figure 3-36: Solar tower used for gas turbine operation in a combined cycle power plant
Figure 3-37: SOLGATE solar powered gas turbine test arrangement on top of the CESA-1
solar tower test facility at the Plataforma Solar de Almeria, Spain (SOLGATE
2005), LT low temperature, MT medium temperature, HT high temperature
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3.7 CSP TECHNOLOGY DEVELOPMENT OUTSIDE EUROPE
3.7.1 Acciona Energia
Acciona Energia is a part of Acciona, a big Spanish infrastructure and services
group. This group is active in wind energy (at the end of 2007 the company installed
about 5000 MW) and also in the field of mini-hydro, cogeneration, biomass and
hydrogen.1 Acciona Energia works with all three solar technologies -CSP, PV and
solar hot water - amounting to a total owned capacity of 195 MW. At the beginning of
summer 2007 Acciona connected to the grid the largest CSP facility of its type in the
world in the last 17 years: the 64 MW Nevada Solar One plant. Acciona is planning
various CSP plants in Spain - all of which have a capacity of 50 MW, upper limit for
the Spanish feed-in law for renewable energies- and participates to the major
projects in the south-western United States.2 Table 6 summarizes Acciona’s already
on-line projects.
Table 3-4: CSP projects of Acciona Energia in the US (by kernenergien)
Nevada Solar One is an Oil-ISG power plant with a gas co-firing unit that provide
additional heating. The plant covers ca. 140 hectares of the desert near Boulder City
in Nevada, south of Las Vegas. The German company Schott has provided 19300
PTR-70 receivers, which are vacuum tubes which absorb the reflected sunlight. They
are located inside parabolic mirrors that are supplied by Flabeg, another German
company. 3 The HTF contained in the receivers is heated up to 300 °C by the
absorbed solar energy and is used to heat water into steam. The steam is then used
to turn a turbine and generate electricity.
1 Concentrating Solar Power: Technology, Cost and Markets. 2008 Industry Report,
Prometheus Institute 2 http://www.acciona-energia.com/default.asp?x=00020204 3 http://www.reuk.co.uk/Nevada-Solar-One.htm
Installation Technology Location On-line Capacity
[MW]
APS Saguaro Project Trough-ORC Tucson, AZ, USA 2006 1
Nevada Solar One Trough- ISG Eldorado Valley, Boulder City, USA Jun 07 64
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Figure 3-38: Nevada Solar 1 64 MW power plant supplying electricity to Las Vegas, US
The plant has an annual output of about 130 GWh: therewith it’s possible to power
more than 14000 households; the electricity production costs are estimated of 0.17
$/kWh and the O&M costs are about 0.05 $/kWh. Even if the price of produced
electricity is higher than the electricity produced by the conventional power plants,
because of tax credits, government subsides and a 20 years power purchase
agreement (PPA) with Nevada Power and Sierra Pacific the plant is able to compete
effectively in the peak power generation market.4
The APS Saguaro Project is a small (1 MW) Trough-ORC power plant located in
Tucson, Arizona. A buffer tank provides storage for short periods without direct
irradiation. The heated oil flows across the solar field and delivers heat an organic
Rankine cycle (ORC) using pentane in a closed cycle that is cooled by a water-
cooled condenser.
4 Concentrating Solar Power: Technology, Cost and Markets. 2008 Industry Report,
Prometheus Institute
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3.7.2 Solel Solar Systems
Solel Solar Systems is a multinational company based in Israel, with subsidiaries
Solel Inc. in the USA and PASCH Y CIA in Spain. Solel was the original supplier of
the solar field for SEGS plants in California and has continued to implement trough
technology to offer solar fields with improved performance. Actually Solel has an
agreement for a 553 MW Power Purchase Agreement with California’s Pacific Gas &
Electric Company and is planning several 50 MW power plants in Spain. Solel
manufactures evacuated receiver tubes and parabolic trough collectors for external
sales, too.5 The company has developed the vacuum receiver element for parabolic
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3.7.4 Skyfuel
Skyfuel was founded in 2005 by Arnold Leitner, the chairman of the Solar Electric
Division of the American Solar Energy Society (ASES). Skyfuel is implementing
trough and LFR technology with RefletechTM reflective films. The company has
received a grant from the New Mexico Energy Innovations Fund and from the Solar
Energy Technologies Program of the U.S. Department of Energy (DOE/SETP):
therewith Skyfuel is currently developing its first installations. 8 With the DOE's
support SkyFuel plans to set up the LTP by 2011.9
RefleTech Solar Film is a high-reflective, silver-metallised film. It is designed for CSP
technologies as well as for other reflector applications that require outdoor durability.
The product is an invention of RefleTech and the NREL. RefleTech Solar Film is
made up of multiple layers of polymer films with an inner layer of pure silver to
provide high reflectance. This special assembly defends the silver layer from
oxidation.10 Figure 3-41 shows the reflectance of RefleTech as a function of the
light’s wavelength.
Figure 3-41: Inspection of Refletech Film Reflectors at SEGS VI and Skyfuel Refletech`s
Reflectance performance over wavelength (http://www.skyfuel.com/)
8 Concentrating Solar Power: Technology, Cost and Markets. 2008 Industry Report,
Prometheus Institute 9 http://www.renewableenergyworld.com/rea/news/story?id=50739 10 http://www.skyfuel.com/
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3.7.5 Brightsource Energy / Luz II
BrightSource is a privately held company and its investors include: VantagePoint
Venture Partners, Google.org, BP Alternative Energy, Chevron Technology Ventures,
StatoilHydro, Draper Fisher Jurvetson, DBL Investors, and Black River. Arnold
Goldman, who founded also Luz International, Ltd., created also BrightSource
Energy. The Luz International was the company that built the 9 Solar Electricity
Generating Stations (SEGS) in California’s Mojave Desert.
Actually, Luz II is focusing on Distributed Power Towers (DPT) technology. LUZ II
plants produce electrical power by using solar energy in order to convert water to
superheated steam. Solar fields reflect sunlight onto a receiver located on the top of
a Power Tower. Each Power Tower module is linked by pipelines to a central location
where superheated steam and electricity are produced. The first installation is
operating in Israel as a pilot plant (Figure 3-42). The facility produces superheated
steam but not yet electricity.11
A series of 100 MW and 200 MW commercial solar power plants are scheduled to
come on line in 2010. LUZ II’s DPT technology consists of a number of solar clusters,
each including a power tower surrounded by an array of heliostats. Heliostats are flat
glass mirrors which track the sun and reflect sunlight onto a receiver. The receiver is
located on the top of the power tower. Power towers are linked together by pipelines
to a central location where electricity is generated and sent to a power grid. The DPT
550 technology heats water to superheated steam at pressures up to 160 bar and
temperatures up to 565 °C. A high efficiency steam turbine converts the superheated
steam to electricity, which is sent to a power grid.
Figure 3-42: Brightsource distributed power tower pilot plant
11 http://www.luz2.com/
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3.7.6 Solar Reserve
The United Technologies Corporation and the US Renewable Group joined forces in
early 2008 to create Solar Reserve, a company dedicated to the development of
molten salt tower power plants. UTC, trough Rocketdyn, Pratt & Whitney and
Hamilton Sunstrand pioneered this technology trough the development of the now
decommissioned Solar One and Solar Two tower installations. UTC has granted
Solar Reserve an exclusive worldwide license to this technology and its full technical
support. US Renewables Group, a $575 M private equity firm exclusively focused on
the development of renewable energy and clean fuel projects, contributes its financial
experience to the new company.12
3.7.7 eSolar
eSolar, based in Pasadena (California) is the utility-scale solar company and has
developed a cost effective utility-scale CSP power plant that is based on mass
manufactured components and designed for rapid construction, uniform modularity,
and unlimited scalability. The eSolar approach offers a low-impact and pre-fabricated
design to provide solar electricity ranging from 33 MW to over 500 MW (see Figure
3-43). The eSolar™ solution delivers cost competitive solar energy in order to meet
the growing worldwide energy demands. The company is supported among other by
Idealab and Google. 13 In June 2008 eSolar declared that it will build plants for
Southern California Edison for a total capacity of 245 MW.14
Figure 3-43: eSolarTM 33 MW Power Unit (http://www.esolar.com/esolar_brochure.pdf)
12 Concentrating Solar Power: Technology, Cost and Markets. 2008 Industry Report,
Prometheus Institute 13 Concentrating Solar Power: Technology, Cost and Markets. 2008 Industry Report,
Prometheus Institute 14 http://news.cnet.com/8301-11128_3-9980815-54.html?tag=mncol;txt
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3.8 CURRENT CSP PROJECT DEVELOPMENT (MARCH 2009)
The current development of CSP projects is very dynamic and therefore difficult to
assess. At the end of 2008 approximately 482 MW capacity of commercial plants
were in operation of which almost 419 MW were installed in the USA, 63 MW in
Spain and another 0.36 MW in Australia. The concept mostly used is parabolic
trough mirrors with an overall capacity of 468.8 MW. The remaining 13.36 MW are a
tower project in Spain with 11 MW and a Fresnel reflector system with 2 MW in Spain
and another one in Australia with 0.36 MW capacity (Table 3-7).
Most of the existing capacity was built in a period from the mid 1980ies to the early
1990ies. The development back then was ascribed to the oil shock in the late 70ies
and the resulting rise of electricity prices. As the prices declined shortly afterwards no
further CSP projects were initiated between 1991 and 2005 due to the decreased
competitiveness and missing political support for this technology (Figure 3-44).
Figure 3-44: Development of Crude Oil Prices since 1960 (TECSON 2009)
With strongly increasing fuel prices the use of renewable energies became more
important in recent years and several governments adopted promotion schemes. The
use of CSP is now also experiencing a revival. In 2007 three installations with a total
capacity of about 75 MW came into operation followed by another installation with 52
MW in 2008. After a steep fall of oil prices from over 90 $/bbl average in 2008 to 40
$/bbl starting 2009, the oil price is again steadily increasing, regaining a level of 55
$/bbl by May 2009. At the same time the cost of raw materials like steel and the
capital cost (loan interest rates) for CSP plants declined considerably. Therefore, the
momentum created for CSP development in the recent years will most probably
continue further.
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Table 3-7: CSP plants in operation in spring 2009.
Plant name Net Power Capacity
[MWe]
Type Constructor Country Year of initial
operation SEGS 1 13,8 Parabolic trough Luz USA 1985 SEGS 2 30 Parabolic trough Luz USA 1986 SEGS 3 30 Parabolic trough Luz USA 1987 SEGS 4 30 Parabolic trough Luz USA 1987 SEGS 5 30 Parabolic trough Luz USA 1988 SEGS 6 30 Parabolic trough Luz USA 1989 SEGS 7 30 Parabolic trough Luz USA 1989 SEGS 8 80 Parabolic trough Luz USA 1990 SEGS 9 80 Parabolic trough Luz USA 1991 Arizona Public Services Saguaro Project
1 Parabolic trough Solargenix Energy
USA 2006
Nevada Solar One
64 Parabolic trough Acciona/ Solargenix
Energy
USA 2007
PS10 11 Tower Abengoa Solar
Spain 2007
Liddell Power Station
0.36 Fresnel reflector Australia 2007
Andasol 1 50 Parabolic trough Solar Millenium and ACS/Cobra
Spain 2009
Puerto Errado 1
2 Fresnel reflector Tubo Sol Murcia, S.A.
Spain 2009
About 16 projects were under construction in spring 2009 summing up to a capacity
of 540 MW. Again Spain with 389 MW and the USA with 86 MW are the largest
contributors to this development. The remaining projects are constructed in Egypt (25
MW) as well as Algeria (20 MW) and Morocco (20 MW).
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Table 3-8: CSP plants under construction in Spring 2009.
Plant name Net Power Capacity
[MWe]
Type Constructor Country
Martin Next Generation Solar Energy Center
75 ISCC FPL USA
Andasol 2 50 Parabolic trough Solar Millenium and ACS/Cobra
Spain
Andasol 3 50 Parabolic trough MAN Solar Millenium (JV MAN Ferrostaal + SM), Duro Felguera
S.A. Energía, Gijón [2]
Spain
Extresol 1 50 Parabolic trough ACS/Cobra Spain Solnova 1 50 Parabolic trough Abengoa Solar Spain Solnova 3 50 Parabolic trough Abengoa Solar Spain Puertollano 50 Parabolic trough Iberdrola Spain La Risca 1 or Alvarado 50 Parabolic trough Acciona Spain Kuraymat Plant 25 ISCC Solar Millenium Egypt Hassi R'mel 20 ISCC Abengoa Solar Algeria Ain Beni Mathar Plant 20 ISCC Abengoa Solar MoroccoPS 20 20 Tower Abengoa Solar Spain Solar Tres 19 Tower Sener/Torrosol Spain Esolar Demonstrator 5 Tower Esolar USA Kimberlina 5 Fresnel Ausra USA Keahole Solar Power 1 Parabolic trough Sopogy USA
The dominating technology is once again parabolic trough. Eight projects use this
technology summing up to an overall installation of 351 MW. Another four projects
are hybrid installations so called Integrated Solar Combined Cycle (ISCC) plants.
This technology combines a solar field of parabolic trough collectors with a gas fire
combined cycle plant.
Tower technology is applied in three projects under construction at the moment
aiming for 44 MW of installed capacity. The Fresnel technology is currently in the
process of installation in one project in the USA. Figure 3-45 shows CSP capacities
currently in operation or under construction per country.
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505 452
0.36
total1,022 MW
20 20 25
505 452
0.36
total1,022 MW
20 20 25
Figure 3-45: CSP capacities in operation or under construction at the end of 2008.
It is not clear how large the number of currently planned installations is. Declarations
of intend can be found on many different levels regarding existing technology as well
as demonstration projects of new technological developments. The status of many of
these projects is constantly changing. Figure 3-46 and the following Tables give an
overview of announced projects at the end of 2008 excluding political goals like
Chinas target to install 1,000 MW CSP capacity until 2020.
Overall 5,975 to 7,415 MW planned capacity of CSP plants could be identified on a
project level that was announced until the end of 2008 (Figure 3-46). The countries
that account for the majority of these projects are once again the USA and Spain.
Table 3-9 shows a detailed list of the announced installations in the USA that
amounted to 3,407 to 4,847 MW. Another 1,980 MW are planned in Spain (Table
3-10). It can be observed that the list of projects in Spain is a lot larger than the one
in the United States even though the overall announced capacity is smaller. The
reason for this is the promotion scheme of Spain that provides a feed in tariff for
installations up to 50 MW. The remaining announcements of another 588 MW
planned capacity can be found in various other countries (Table 3-11).
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3,407 – 4,847 1,980
10010
124
10250
100
total5,975-7,415 MW
50523,407 – 4,847 1,980
10010
124
10250
100
total5,975-7,415 MW
5052
Figure 3-46: Announced CSP installations at the end of 2008.
Table 3-9: Announced CSP installations in the USA.
Plant name Net Power Capacity
[MWe]
Type Constructor Country
Ivanpah 1 123 Tower Brightsource USA Ivanpah 2 100 Tower Brightsource USA Ivanpah 3 200 Tower Brightsource USA (Brightsource other) 100 (+400) Tower Brightsource USA Mojave Solar Park 553 Parabolic trough Solel USA SES Solar One 500 (+300) Dish Stirling Energy
Systems USA
SES Solar Two 300 (+600) Dish Stirling Energy Systems
USA
Solana 280 Parabolic trough Abengoa USA Carrizo Solar Farm 177 Fresnel Ausra USA Beacon Solar Energy Project
250 Parabolic trough FPL USA
Gaskell Sun Tower 105-245 Tower Esolar USA San Joaquin Solar 1 & 2 107 Parabolic trough Martifer Renewables USA City of Palmdale Hybrid Power Project
62 ISCC USA
Harper Lake Energy Park
500 Parabolic trough USA
Victorville 2 Hybrid Power Project
50 ISCC USA
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Aste 1 A 50 Parabolic trough Aries Spain Aste 1 B 50 Parabolic trough Aries Spain Aste 3 50 Parabolic trough Aries Spain Aste 4 50 Parabolic trough Aries Spain Astexol 1 50 Parabolic trough Aries Spain Astexol 2 50 Parabolic trough Aries Spain Puerto Errado 2 30 Fresnel Tubo Sol Murcia,
S.A. Spain
La Risca 2 50 Parabolic trough Acciona Spain Palma del Rio 1 50 Parabolic trough Acciona Spain Palma del Rio 2 50 Parabolic trough Acciona Spain Consol 1 50 Parabolic trough Conergy Spain Consol 2 50 Parabolic trough Conergy Spain
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Table 3-11: Announced CSP installations in various other countries.
Plant name Net Power
Capacity [MWe]
Type Constructor Country
Ashalim
250 Parabolic trough Israel
Uppington 100 Tower Eskom South Africa
Shams 100 Parabolic trough ABU DHABI
Cloncurry solar power station
10 Tower Ergon Energy Australia
Archimede 3,75 ISCC Enel etc. Italy Solenha 12 Parabolic trough Solar Euromed France Theseus Project 52 Parabolic trough Solar Millenium Greece 50 Parabolic trough Solar Millenium China 10 ACME India
As the development is rapid and many projects might have slipped through the
collection displayed above a number of other publications will be referenced in the
following.
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3.9 REVIEW OF CSP INDUSTRY (MARCH 2009)
In a recent report titled “The CSP Industry – An Awakening Giant”, the Deutsche
Bank predicts strong structural growth prospects for CSP industry in the coming
decades (Deutsche Bank 2009). This view of a major global financing institution
coincides very well with present project development activities, with the appearance
of many new CSP designs and players all over the world, with the implementation of
suitable financing instruments like feed-in tariff systems and tax credits by many
governments and with the deficiencies of the fossil and nuclear energy supply system
of the past century becoming more and more obvious. CSP is getting into the minds
of investors and politicians as a very large renewable energy source that can deliver
electricity on demand.
Table 3-12 gives an overview of companies currently involved in the project
development, engineering, procurement, construction and operation of CSP plants
and of their role in the CSP market.
Table 3-13 names players from research and development, investors, utilities and
lobby groups presently involved in CSP deployment.
The list does not claim to be complete, as new players appear almost daily.
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Table 3-12: Overview of present CSP Industries
Companies Project Develo pment
F inancial Engineering
Engineering Procurement, Technology
Co nstructio n Operation & Ownersh ip
Site qualif ication,
feasibility study, pre-planning, regulatory, economic and
technical analysis
Devise viable
f inancing structure and provide for f inancing, investor
relations
Detail planning &
implementat ion, plantlayout, quality management,
supervision
Supply technology -
receiver, mirrors, support structure, power block, thermal
storage etc.
Construct ion works Hold, buy and sell
shares in the power plant, operate plants
Abener X X X
Abengoa S.A. X X X X X X
Acc iona Energía X X X (X) X X
ACS Cobra X X X
Albiasa Solar X
Alstom X
Aries X X X X
Astrom X
Ausra X X X X
Babcock Montajes X
Balcke-Dürr X
Bright Source Energy Inc. X X X X (X) X
Défi-Sys témes X
Endesa X
ENEL X
Enolcon X X
Eners tar X
Enviromission X X X (X) (X)
Epuron X X X
Eskom X X (X) X
Fichtner X (X)
Flabeg X
Flagsol X X
FPLEnergy X X X X
GE X
GEA Ibérica X
Goldman Sachs X
Guardian X
Iberdrola X X
Iberinco X X X
KAM X X X
kernenergien X
Lahmeyer X X
M&W Zander X X X
MAN F errostaal X
Morgan Stanley X
NEAL X X
Novatec Biosol AG (X) (X) X X X X
Orascom X X
PG&E X
Rioglass X
Sacyr Vallehermoso X
Saint Gobain X
Schlaich Bergermann (X) X
Schott Solar X
Sener X (X) X (X)
SES X
Siemens X
Sky Fuel X X X (X) (X)
Solar Heat and Power (X) (X) X
Solar Millenium AG X X X X X X
Solar Power Group (X) (X) X
Solargenix Energy LLC X X X (X)
Solel Ltd. X X X (X)
SPX Cooling X
Sti rling Energy Sys tems X X (X) X X
Thermodyn X
Torresol X Sources: Deutsche Bank 2009, EuPD Research 2008, new energy finance 2008, DLR
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Table 3-13: Other Players involved in CSP
Research & Developmen t Util ities Investors / Credito rs L obbies & Asso ciations
Solar resource
assessment, systems analysis, technology assessment, system and
component development, basic research
Ut ility Services, Sales,
Trade, Power Purchase Agreements
Equity Inves tment, Loans ,
F inancial Engineering, Support, Grants
Lobby ing, campaigning,
information
CENER APS ADB D ESERT EC Foundat ion
CERT H ENDESA Banc Sabadell ESTELA
CIEMAT ENEL Banesto Greenpeace
CNRS ESKOM Caja Madrid SEIA
DLR Iberdrola Calyon SolarPaces
Fraunhofer ISE NEAL CAM SW-CSP Initiat ive
IDAE Nevada Solar Cof ides T REC
INETI ONE Commerzbank
IRSOLAV Sierra Pacific EIB
Mines-ParisT ech F idelity
NASA ING
NREL JBIC
PSI KfW IPEX
SUNLAB Lupus Al pha
SUNY Masdar
Weizmann Ins t. Nat ixis
Piraeus Bank
Santander
SI capital
Societé Generale
Swisscanto
Ubibanca
UBS
Union Invest
W est LB
W orld Bank / GEF Sources: EuPD Research 2008, DLR, Deutsche Bank 2009
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4 TASK 2: DESALINATION TECHNOLOGY REVIEW
4.1 Introduction
Over time a lot of different desalination technologies have been invented for small
and large application. The basic principle for several methods will be described. This
study focuses on cogeneration of power and sea water desalination therefore a more
detailed thermodynamic analysis of membrane and thermal desalination follows. The
concentration of salt in water is described by the total dissolved solid content (TDS)
or salinity in mg salt per l water. The following list shows the classification of saline
water based on the TDS:
River water / low concentrated brackish water 500 – 3.000 mg/l TDS
Brackish water 3.000 – 20.000 mg/l TDS
Sea water 20.000 – 50.000 mg/l TDS
Brine > 50.000 mg/l TDS
The WHO recommends water with a salinity below 1000 mg/ l for drinking water and
irrigation. Industrial processes or process water for power plants require a much
higher water quality with a TDS less than 10 mg/l. This can be provided by thermal
distillation processes in a single step. However, if this water shall be used for drinking
water minerals have to be added again. The report, starting with a short retrospection
into the past, covers most of the technologies available with a strong focus on state-
of-the-art for the site studies.
Already Aristotle, considered the last philosopher who was probably the last person
to know everything there was to be known in his own time has written about seawater
distillation. Abu al-Mansur al Muwaffak an early islamic scientist reported about
distillation to produce drinking water from sea water in the 10th century. /Levey
1973/.
The first patents for seawater distillation in the history of western science have been
published at the end of the 17th century, 1675 by William Wilcot and followed 1683
by Robert Fitzgerald /Forbes 1970/. This lead to an early dispute about the patents,
with interests of the crown of England colliding with inventors rights /MacLeod 2002/.
The term of “osmosis” in connection with liquid phase separation by a membrane has
been described in 1748 by J.A. Nollet. 200 years later “reverse osmosis” started to
become the leading technology for desalination by membrane processes.
One of the first, if not the first thermal heat pump at all has been described already in
1834 by Pelletan. Pelletan published a heat pump with a steam ejector in order to
recover the heat of evaporation from a salt concentrator.
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Figure 4-1: Submerge tube 1904; courtesy of Weir Westgarth, company presentation 2003
In 1879 the first patent for mechanical vapor compression has been filed. At the turn
of the century, in 1900, the multi flash distillation process was invented, followed
1908 with the first patent for TVC (thermal vapor compression). The first multi effect
evaporators have been built in the middle of the 19th century. A typical application
for small distillation units in this time was on ships (see Figure 4-1). From this time
onward sea water distillation became more and more sophisticated with the main
technologies described in the following chapters.
In the following chapter the most important desalination technologies will be
described. Included are well developed state of the art technologies like MSF, MED
and RO as well as new developments (MEH, VMEMD). Distilled water can be
produced from saline water by two main processes, evaporation and separation
through membranes (Table 4-1). The driving energy for both processes can be either
electrical power or thermal energy.
Thermal desalination plants use heat sources as the driving force. These heat
sources can be hot water or steam from a turbine. Therefore thermal desalination is
ideal for co-generation with power plants. Electrical power is only necessary for
parasitical internal demands such as pumps etc.
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Table 4-1: Overview of desalination technologies
Process
Driving power
Evaporation Membrane
Thermal Multi Stage Flash (MSF)
Multi Effect Distillation (MED)
Solar Stills
Multi Effect Humidification
(MEH)
Vacuum Membrane Distillation
(VMemD)
Electrical Mechanical Vapour
Compression (MVC)
Electro Dialysis (ED)
Reverse Osmosis (RO)
4.2 Evaporation Processes
4.2.1 Mechanical Vapour Compression MVC
A mechanical vapour compression MVC unit is essentially an MED unit. Like with a
MED process sea water is sprayed on the tube surface. The evaporated water will be
compressed in a mechanical compressor. The compressed steam is condensed and
exchanging heat again with the sea water. MVC plants are driven by electrical power.
The advantage of a MED with mechanical vapour compressor is, it does not need
steam and is very robust like all MED. But the compressors are expensive, though
compressors with higher compression ratio are available now. Usually fans with a low
compression ration are used with p/p0 < 1,3. higher compression ratio requires axial
compressors which are very expensive.
A MED-MVC requires large heat transfer surface in order to achieve low power
consumption. Large pre-heaters have to be installed to maintain evaporation at
roughly 55-65°C. Their size is limited by the availability of the compressors suction
flow rates.
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Evaporator 1 Evaporator 2
Brinepump
Distillatepump
Sea waterinlet
Compressor
preheater
Evaporator 1 Evaporator 2
Brinepump
Distillatepump
Sea waterinlet
Compressor
preheater
Figure 4-2: Scheme of mechanical vapour compression
4.2.2 Multi Stage Flash desalination (MSF)
A multi stage flash desalination plant consists of several serial stages of
chambers/vessels. The upper parts are condensers. Each stage is operated at about
2-5 K lower temperature than the previous one. The number of flash stages can vary
form 10 to 30. The sea water is heated step by step in the condenser tubes. In the
last step sea water is heated by hot water or steam from an external source in the so-
called brine heater. The hot sea water is then flashed into the first chamber and
partly evaporated. The generated steam is condensed and collected to be used as
the distillate.
MSF plants are extremely robust and have a high reliability with long running periods
between cleaning (6 - 24 months). They can treat very saline raw water and still
produce good distillate quality (typically 1-10 ppm TDS). Inside the condenser tubes
there is only single phase heat transfer and no degassing inside heat exchangers
which in turn reduces scaling. However MSF plants are rather expensive needing
large specific heat transfer surfaces. Further the electrical energy consumption is quit
high compared to other thermal systems (3-4 kWh/t). The MSF have been the work
horse of desalination for more than 40 years.
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steam
Brinepump
Distillatepump
Sea waterinlet
Figure 4-3: Scheme of the MSF process
4.2.3 Multi Effect Distillation (MED)
A multi effect distillation plant consists of several stages of evaporators under
vacuum. Sea water is distributed on the outer surface of the tubes and partly
evaporated. The driving heat of the first evaporator is hot water or low pressure
steam from an external source with a maximum temperature of 70°C. All other
evaporators use the evaporated water vapour of the previous stage as heat source.
This steam condenses and will be used as process or drinking water.
Lowpressuresteam
Evaporator 1 Evaporator 2 Evaporator n Condenser
Brinepump
Distillate pump
Sea waterinlet
Brineoutlet
Lowpressuresteam
Evaporator 1 Evaporator 2 Evaporator n Condenser
Brinepump
Distillate pump
Sea waterinlet
Brineoutlet
Figure 4-4: Scheme of the MED process
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Like the MSF, MED plants can treat very saline raw water and produce good distillate
quality. They are also highly reliable with long running periods between cleaning (6 -
24 months). MEDs are less expensive than MSF since they need a much smaller
heat transfer surface. Further no sophisticated equipment is required. MEDs have a
better thermal efficiency and very low electrical consumption (0.5-0.6 kWh/t). The
heat transfer in MED is with dual phase flow, thus degassing occurs during
evaporation. However the tube surface can only be cleaned chemically. The
maximum steam temperature is limited to 70°C due to scaling, i.e. the number of
stages is also limited.
Recent developments for both MSF and MED include upstream removal of Ca and
Mg by nano-filtration (NF) as well as degassing and acid dosing to remove CO2 and
reduce vacuum pumping, which may have a potential to increase. The downside,
however is a significant increase in complexity.
4.2.4 Multi Effect Distillation with Thermal Vapor Compression (MED–TVC)
If high pressure steam from a power plant is available, the output of a MED plant can
be further enhanced using a steam ejector. The high pressure steam is the motive
steam, providing the energy for recompression of the product vapour from the
evaporator. This vapour leaving the thermo-compressor, which will be at an
intermediate pressure level, is again used as driving heat for the first evaporator.
High pressuresteam
Evaporator 1 Evaporator 2 Evaporator n Condenser
Brinepump
Distillate pump
Sea waterinlet
Brineoutlet
Thermo compressor
Steam transformer
High pressuresteam
Evaporator 1 Evaporator 2 Evaporator n Condenser
Brinepump
Distillate pump
Sea waterinlet
Brineoutlet
Thermo compressor
Steam transformer
Figure 4-5: Scheme of a MED-TVC
A MED with thermal vapour compressor can benefit of heat at higher temperatures,
without increasing the top brine above the critical scaling temperature of 65-70°C.
There are very simple and robust skid mounted units with smaller size steam piping
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available. However, MED-TVCs have a lower thermodynamic efficiency than a
simple MED. A steam transformer is mandatory if clean distillate in first cell is
required. Recently, steam compressors with low motive steam pressure (1-2 bar
abs.) have been developed. All systems are quite robust. The operation is simple
and fault tolerant to a very high degree.
4.2.5 Solar Stills
A rather simple technology is the so called “solar still” using the solar energy
directly./Holland 1999/
The glas roof covers the basin of saline water (see figure 6). Water volatilises under
the influence of solar radiation. A dark underground of the pond enhances the
evaporation. The water is then condensed underneath the glass surface, which is
cooled by the ambient air. The condensate is recovered on both sides of the
construction. These stills are used for small scale applications, the daily production
being limited to about 5 l per square meter.
Solar stills do not require any auxiliary power nor any control and can be erected with
a minimum of materials of construction. Feed flow can be kept very low as solar stills
operate up to high salt concentrations including crystallisation. This technology is
also called “solar distillation”. This can be confused with the expression of “solar
powered desalination”. The later term describes in particular desalination processes
in co- generation with solar power plant, as studied in this and other projects /Trieb
2007/.
Figure 4-7: Principle of a solar still
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4.2.6 Multi Effect Humidification (MEH)
Multi effect humidification is based upon the principle of solar stills /Müller-Holst
2002/. An isolated chamber consists of an evaporator section and a condenser
section. Hot sea water is distributed on top of the evaporator section, which is
constructed with parallel plates. Part of the water evaporates while flowing downward
and cooling down. At the same time air flows up through natural convection and
becomes more humid through absorbing the water vapor.
Cold sea water flows from bottom to top in the condenser section exchanging heat
with the down flowing air. Water condenses on the heat exchanger surface and is
collected at the bottom. Brine is collected at the bottom of the evaporator section.
The sea water is further heated up to 85 °C by an external heat source like hot water
or steam.
Figure 4-8: Principle of humid air distillation
Facts about the system and its advantages:
Low temperature heat of 85°C is used for evaporation
∙Absence of moving parts within the distillation chamber ensure low
maintenance demand
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The self-controlling natural convection loop enables best energy recovery
ratios of up to GOR 8
Sophisticated geometrical design allows easy maintenance and optimum
performance at the same time
No pre-treatment of raw water is needed. The process is insensitive to high
salt contents.
Modular set-up, available sizes comprise units with 1000, 5000 and 10000
litres per day capacity
Figure 4-9: MEH field study near Dubai; pictures courtesy of Almeco-Tinox GmbH
A complete autonomously driven desalination system is operating since July 2008 in
the middle of the desert south of Dubai, using fossil high alkaline brackish water as
raw water source. /Müller-Holst 2009/. The system is equipped with solar thermal
collector field of 156 m² absorber area and a PV electrical energy supply of 4.8 kW
peak. The System is running in 100% stand alone operation mode, as no grid
connection is available.
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4.3 Membrane Processes
The purpose of membranes is the separation of phase (liquid/ vapour) or molecules
and ions. For phase change membranes the driving force is heat. Evaporation occurs
in the membrane because of vapour pressure difference on either side of the
membrane and thus dividing the liquid from the vapour.(see chapter 2.2.3 VMEMD).
The other separation process is diffusion. Only Molecules or ions which are small
enough can pass through the pores of a membrane. The driving force is a difference
of chemical potential, which can be either pressure or electrical voltage.
Electrodialysis separates the ions from water by using direct current across the
membrane which an ion conductor. The membrane selectively lets pass the ions
leaving distilled water behind.
The membrane in the reverse osmosis acts like a filter, letting pass the water
molecules and leaving the ions of the brine behind. Electric pumps generate the
necessary high pressure up to 70 bar for sea water desalination in RO while a
differential voltage is applied across an ED membrane.
Saline Water Saline Water
Brine
Brine
Distillate
Distillate
Reverse OsmosisElectro Dialysis
Saline Water Saline Water
Brine
Brine
Distillate
Distillate
Reverse OsmosisElectro Dialysis
Figure 4-10: Comparison of electro dialysis and reverse osmosis
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4.3.1 Electro Dialysis
Figure 10 shows the schematic process of the electro dialysis process. The cathode
and anode envelope a block of membranes. Two different kind of membranes
alternate – one selective for anions the other for cations.
Saline water is distributed into the channels between the membranes. The salt in the
water then ionises when the electrical field is applied. In every second channel the
water is enriched salt other channel depleted with salt. The two streams, distillate
and brine, are collected at the bottom of the cell.
Electrodialysis processes are used for brackish water desalination only. Newest
plants have output rates over 20.000 m³/d. To date there do not seem to be any SW
ED plants./IDA 2008/.
Figure 4-11: Electrodialysis process
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4.3.2 Reverse Osmosis
Since their introduction in the late 1950's, reverse osmosis, nano-filtration, ultra-
filtration and micro-filtration have been increasingly used in the field of water
treatment. From the early development by Sourirujan and Loeb on the spiral wound
cellulose acetate membrane and the invention of capillary technology, has improved
performance, reliability and lower operating cost, making membranes the preferred
technology for desalination of seawater, brackish water and waste water.
In the last decade RO seawater desalination has gone through a significant
transformation. Currently most of implemented seawater desalination plants use RO
technology. System of 300,000 m3/day and recently even larger, have been build and
are in operation in many parts of the world. Desalted water cost decreased from 2.0
$/m3 to 0.5 $/m3 and world wide capacity is continuously increased
In Israel, same as in the Mediterranean region, reverse osmosis (RO) is almost
exclusively the leading technology. A considerable advancement was achieved in
many areas of this technology: in the pre-treatment in the membranes and in the
pumping and energy recovery systems. Osmosis is a physical process, which takes
place when two solutions of different salt concentrations are separated by a semi
permeable membrane.
Figure 4-12: Explanation of Reverse Osmosis
Under normal conditions (A) (see Figure 4-12) water will pass from the solution
whose salt concentration is higher until the hydrostatic pressure difference is
equalized, or more precisely, the passage of water through the membrane in both
directions will be equal. The pressure difference between distilled water and any
saline solution, when the flow of water in both directions is identical, is equal to the
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osmotic pressure of the solution (B). The application of an external pressure on the
concentrated solution (C), which is larger than the osmotic pressure will cause water
flow from the concentrated solution to the dilute solution through the membrane, this
process is called reverse osmosis. This osmotic pressure is proportional to the salt
concentration. In the Mediterranean waters it is approximately 30 atmospheres.
Figure 4-13: Principle of Operation of Seawater RO (SWRO) Desalination Plant - Process
Flow Diagram
4.3.3 Vapor Membrane Distillation (VMEMD)
The main principle of membrane distillation is the following: two chambers are
divided by a micro-porous, hydrophobic membrane. One chamber contains the saline
water. The other side only water vapour. If heat is applied to the water side of a
pressure difference occurs between the chambers – the lower pressure being on the
vapour side – and water vapour permeates though the membrane. Up to now
membrane distillation is a process similar to the MSF.
A newly developed technique is the vacuum membrane distillation. I combines the
distillation via membrane with a MED process./Heinzl 2009/.
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Stage 1 Stage 3Stage 2 Brine
CondenserHeating steam
from external heat source
for exemple power station
DistillatePreheated Feed
Stage 1 Stage 3Stage 2 Brine
CondenserHeating steam
from external heat source
for exemple power station
DistillatePreheated Feed
Figure 4-14: Vapour membrane distillation process
Preheated sea water enters into the channel of stage 1, which is enclosed on one
side by a condensing non-permeable membrane and on the other side by a
hydrophobic but permeable membrane. The condensing membrane of the first stage
is heated by hot water or steam. Thus heat is transferred to the sea water. The
pressure p2 of the second stage is lower than in the first stage. Water evaporates
through the membrane into the second chamber. This vapour condensates again at
the condensing membrane of the second stage transferring heat to the sea water
chamber. The thermal and electrical power consumption are the same as for MEDs.
The next steps are analogue. Latest developments promise an easy modular
system. Capacities of up to 10.000 m³/d and more can be achieved with serial and
parallel arrays of modules.
Advantages
- no formation of inert gas
- modular design with plate modules
- modules completely pre-manufactured with polymeric material
- pre- and post treatment necessary similar to MED
- high durability of membranes
- non-sensitive against longer stand-still periods
- low investment costs
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4.4 Desalination in the Mena-Region
The figure in Annex 1 show the cumulated number of desalination plants going online
in the last 10 years in the MENA region and their cumulated capacities. This study is
focuses on industrial sized seawater desalination, therefore only plants with an
installed capacity higher than 2000 m³/d are looked at.
The four diagrams in Annex 1 show a comparison of the three main technologies RO,
MSF and MED /DW&R databank/. The characteristics are
‐ the installed plants per year
‐ cumulated number of installed plants
‐ installed capacity per year in m³/d
‐ cumulated capacity in m³/d.
Clearly most new plants in the last 10 years have been build with RO technology.
The cumulated number of installed plants for MSF and MED are almost the same,
each about half as many as RO plants. However the trend of the last few years
shows an increasing preference of MED plants to MSF. Looking at the installed
capacities gives another perspective. Now the MSF technology is in lead. hat the
average capacity of a MSF plant is much higher than of a RO.
The peak capacity of MSF in 2002 is due the installed plants at Shoaiba, Saudi
Arabia, with a capacity of 390.000 m³/d. In 2008 the MSF plant for the extension at Al
Taweelah, United Arab Emirates, came online with a capacity of 315.000 m³/d. The
largest MED plant currently in operation since 2007 is in Al Hidd, Bahrein with a
capacity of 275.000 m³/d. The first RO plant with a capacity larger than 300.000 m³/d
is installed at Ashkelon, Israel since 2005. For the construction of desalination plants
in the future, still the tendency is to build bigger and bigger. The following table
shows some selected projects:
Table 4-2: Selected desalination projects in the MENA region.
Technology Location Daily capacity
[m³/d]
Planned online
date
RO Hadera, Isreal 330.000 2010
MED Marafiq Jubail, Saudi Arabia 800.000 2009
MSF Jebel Ali, United Arab
Emirates
637.000 2011
MSF Shuaiba North, Kuwait 273.000 2010
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4.5 Thermodynamics
4.5.1 Irreversibilities
In theory the work required to desalinate sea water is only 0.6 kWh/m³. But all real
desalination plants, membrane and thermal, are consuming at least 5-10 times as
much work than this figure due to a number of important irreversibilities in any of the
processes available.
Irreversibilites are a measure of second law efficiency, i.e. loss of power production
in the associated power process is proportional to the irreversibilities and the resp.
temperature.
While the nature of irreversibilites are different for membrane and thermal systems,
the impact is the same, once the system is viewed including the generation of power.
Thermal processes
The temperature difference between two evaporation stages can be divided into the
following terms:
— pressure drop of heating steam inside tubes
— heat transfer of condensing steam
— heat transfer across tube wall
— heat transfer form tube wall into sea water
— boiling point elevation 0.35 K for raw sea water
0.7 K for concentrated sea water
— pressure drop of vapour across tube bundle
— pressure drop across demister
In practice the temperature difference between two stages varies between 2 K and 7
K while the thermodynamic minimum is 0.35 K
Reverse Osmosis
— raw water pump efficiency
— pressure drop in pre‐filtration
— pressure drop in cross flow membrane
— polarization on membrane surface
— permeability of membrane
— osmotic pressure 23 bar for raw sea water
up to 35 bar for brine
— pressure recovery system efficiency ( turbine or pressure transformer)
The realistic work required for RO desalination is 3 – 5 kWh/m³ while the
thermodynamic minimum is 0.6 kWh/m³.
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4.6 Reverse Osmosis
4.6.1 Main Characteristics of RO Membranes
The two main characteristics of RO membranes are salt rejection and membrane
permeability.
a. Salt Rejection (Rej, %) is defined according to the following formula:
Rej(%)= 100(1 - Cp/Cfavg)
Cp = permeate concentration
Cf(b)avg = feed(brine) average concentration
Example
Cp = 100 ppm; Cf = 5,000 ppm; Cb = 10,000 ppm
Rej = 100 x (1-100/7,500) = 98.67%
b. Membrane permeability (Ka) is defined according to the following formula:
Ka = Jp/NDP
Jp = average permeate flux: Jp = gpd/A
NDP = net driving pressure: NDP = Pf – Л– dP/2
Pf = feed pressure; Л = average osmotic pressure difference between
the concentrating salts; dP/2 = average hydraulic pressure losses
Л= 1.35 bar (1500 ppm) NPD = 15.85–1.35–0.3 = 14.5 bar
dP/2 = 0.3 bar
Ka = 46.6/14.5 = 3.2 l/m2-hr-bar
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4.6.2 Brackish Water Reverse Osmosis (BWRO)
Desalination of BW is typically implemented for water of 1,500 - 12,000 mg/l TDS.
Unlike seawater where product recovery is limited by high osmotic pressure, brackish
water desalination is limited by the precipitation potential of sparingly soluble salts
such as: CaSO4, SiO2, BaSO4, C2F, SrSO4.
By use of special antiscalants, operation condition of about 300% over-saturation of
CaSO4 and up to 200 ppm SiO2 could be achieved. In most of the cases the product
recovery is in the range of 80 - 90%.
Since energy recovery in BW desalination is not economical in most of the cases, the
product recovery is the most significant parameter determining the energy
requirement. This parameter importance is reflected also in the feed supply and brine
disposal capacities.
The membrane type and flux define the performance of the plant. For surface water
and secondary effluents the membrane flux is usually limited to 18 - 20 lmh, while for
ground water with low SDI - usually lmh of 22 - 24 is applied.
Regarding membranes performance, the main development efforts for the BWRO
application are towards higher module capacity, achieved by a combination of larger
membranes’ area and higher permeability. Typical membrane characteristics of
BWRO membrane modules, developed by two major membranes suppliers:
Hydranautics and Filmtec, are shown in Figure 4-16.
Because of the wide range of feed water types 1,500 - 12,000 mg/l, a relatively wide
range of product recovery (70% - 90%) and use of high and low pressure membrane
types (permeability 3 - 8 lmh/bar), the specific energy of BWRO desalination varies
between low value of 0.4 kWh/m3 to a high value of about 1.7 kWh/m3, as can be
seen in Table 3.
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3.3 3.3
3.94.4
5.15.5
7.5
8.2 8.3
0
1
2
3
4
5
6
7
8
9
99.5 99.7 99.5 99.6 99.6 99.2 99.0 99.2 99.2
34 37 37 37 40 41 41 37 40
CPA2 CPA3 BW-30-400 ESPA2 ESPA2+ BW-30-LE440
BW-300XLE440
ESPA4 ESPA4+
Per
mea
bilit
y, l/
m2 -h
r-ba
r
Rejection rate, %
Area, m2
Membrane type
Figure 4-16: Typical performance of RO membranes of two major membranes suppliers
Table 4-3: Comparative BWRO system performance for two brackish water types and two
membrane types.
Feed water:
Salinity, mg/l 1,500 12,000
Pressure, bar 10.4 30.8
Product:
Recovery, % 90 70
Salinity, ppm TDS 300 360
Membrane type:
Hydranautics ESPA4+ CPA3
- Area,m2 40 37
- Permeability, lmh/bar 8.3 3.3
Specific energy, kWh/m3 0.47 1.73
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4.6.3 Seawater Reverse Osmosis (SWRO)
A system desalination typical Mediterranean water of about 40,000 mg/l TDS at 25 0C, by standard 37.2 m2 spiral wound membranes with permeability of about 0.9
lmh/bar operating at a recovery of 40% and flux of 14.0 lmh uses a pressure of 64.4
bar.
Assuming ηP X ηM = 0.8, the specific energy required without ERD.
3/76.58.04.0
4.640286.0mkWhSE
However, by use of an ERD of a typical Pelton turbine, the specific energy
requirement is reduced by about 40%, to about 3.46 kWh/m3.
In case a more advanced membrane type, such as 9,000 gpd with a permeability of
1.31 lmh/bar will be used, with more efficient process pump (ηP = 89%, ηM = 96%)
and more efficient Pelton turbine (89%), the specific energy consumption will be
further reduced to about 3.0 kWh/m3 for a lmh of 18 and to about 2.82 kWh/m3 for a
flux of 14 lmh.
2.80
2.85
2.90
2.95
3.00
3.05
3.10
3.15
3.20
3.25
30 35 40 45 50 55 60
Recovery, %
Sp
eci
fic
en
erg
y, k
Wh
/m3
50
55
60
65
70
75
80
85
90
95
Fee
d p
ress
ure
, ba
r
Flux = 14 lmh
Flux = 18 lmh
SWRO Desalination PlantFeed water Salinity: 41,000 ppm
Collector Cleaning Spraying Spraying Robots, rinse & brush Spraying SprayingWater Demand low with dry cooling low with dry cooling very low with dry cooling and
robot cleaninglow with dry cooling low with dry cooling
Desalination Options RO or MED RO or MED RO or MED RO or MED RO or MEDExperience long-term commercial experimental recently commercial recently commercial experimentalAnnual Efficiency (%) up to 15% up to 17% expected in future up to 12% up to 16% expected in future up to 25% expected in futureInvestment Cost (€/kW) 3,500-6,500 n.a. 2,500-4,500 4,000-6,000 n.a.General Comments Commercially proven
technology for 20 yearsExpected better cost and performance than oil-cooled trough, but not yet commercial
Lower optical efficiency but also lower collector cost compared to trough
A theoretically better thermal efficiency than trough has not yet been demonstrated
Theoretically better performance and cost than central receiver steam cycle power plant, but not yet commercial
Advantages most experienced system direct steam, no temperature limitation from HTF
direct steam, no temperature limitation from HTF
no temperature limitation from heat transfer fluid
very high temperatures possible > 1000°C
several providers water/steam is low cost and environmental friendly heat transfer fluid
water/steam is low cost and environmental friendly heat transfer fluid
water/steam or air is low cost and environmental friendly heat transfer fluid
very high efficiency possible
reliability proven reliability demonstrated reliability demonstratedDisadvantages risk of molten salt freezing no commercial provider storage options for direct
steam generation not yet commercial
complex construction no commercial provider
complex construction complex construction simple construction very complex constructionrisk of HTF leakage high temperature materialstemperature limitation below 390°C due to heat transfer fluid
Table 5-3: Comparison of the principal features of current CSP systems applicable to seawater desalination
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5.3 INTEGRATION OF CSP AND DESALINATION PLANTS
There are basically two options of combining CSP with seawater desalination that will
be investigated within the MED-CSD project:
5.3.1 Case 1: Reverse Osmosis Powered by Electricity from a CSP Plant (CSP/RO)
The plant configuration of the ANDASOL 1 plant can be considered the status quo of
a modern CSP installation. The plant uses the modern European parabolic trough
collector design SKAL-ET and the new receiver tube Schott Solar PTR-70 for its
solar field. The heat transfer fluid used to transfer the solar heat to the power block is
synthetic oil Monsanto VP-1 operating between 292 °C and 386 °C. The collector
field has an aperture area of 510,000 m² and requires about 2 km² of land. The total
investment is about 310 million Euro.
The plant uses two large tanks containing 28,500 tonnes of molten nitrate salts (60%
NaNO3 + 40% KNO3) to store solar energy received during the day for night time
operation of the turbine. The tanks are 14 metres high and have a diameter of 38.5
metres. The molten salt can store an amount of heat of 1010 MWh which is sufficient
for 7.5 hours of full load operation of the turbine, with a charging capacity of 131
MWth and a discharging capacity of 119 MWth. The heat from the solar field is
transferred to the molten salt tanks via HTF/salt heat exchangers and from the solar
field and the storage to the power cycle via a HTF steam generator. The power cycle
is comprised by a 50 MW steam turbine SST-700RH from Siemens operating with
superheated steam at a pressure of 100 bar and a temperature of 377 °C. A
condenser cooled by a wet cooling tower rejects the heat from the power cycle.
The plant has a gas-fired backup system (HTF Heater) to provide a maximum of 15%
of the required heat when no solar energy is available. It will be used to avoid
transients from clouds and to support start-up in the morning. Under the solar
irradiation conditions given at the plant site in Spain, Andasol 1 will produce about
180 GWh of electricity per year. The plant was build by ACS Cobra and engineered
by Grupo SENER, both well known Spanish companies.
The ANDASOL plant configuration is very well applicable to a CSP/RO concept
producing maximum electricity during the day for RO operation and for surplus power
delivered to the grid, while during night time the plant will operate in part load and
only serve the RO system which will be operated continuously during 24 hours. A
configuration with an RO input power capacity of about 30% of the turbine output
capacity should fit well to the ANDASOL configuration. This must still be confirmed
by hourly time series modelling of plant performance under the concrete conditions
for the sites under consideration. The following pictures give same examples of the
equipment that may be used in this configuration:
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Pre-Heater
Evaporator
Superheater
Re-Heater
Turbine
Cooling Tower
Condenser
Generator
Grid
Feed PumpHeat Transfer Fluid Pump
Solar Collector Field
Storage
Hot Tank
Cold Tank
Pre-Treatment
3 ~
permeate
seawater
energy recovery unit
pump
membrane
Post-Treatment
product
Pre-Treatment
3 ~
permeate
seawater
energy recovery unit
pump
membrane
Post-Treatment
product
Figure 5-3: Combined CSP desalination plant with reverse osmosis (CSP/RO)
Figure 5-4: SKALET parabolic trough collector with 150 metres length.
Hot Salt Tank
Cold Salt Tank
Salt / HTF Heat Exchangers
Hot Salt Tank
Cold Salt Tank
Salt / HTF Heat Exchangers
Figure 5-5: Molten Salt Heat Storage at ANDASOL 1
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Figure 5-6: Photograph showing a 20 MW steam turbine with gearbox (left), low pressure
steam flange (centre, top) and high pressure steam inlet (right, top), Dimensions
L=7m , W= 3m , H=3m. Generator will be connected on the left (Length 5 m).
Figure 5-7: Backup HTF Heaters and Field Piping at SEGS VI, Kramer Junction, USA
Figure 5-8: Left: Pressure cylinders containing the separation membranes of a reverse
osmosis plant in Barcelona, Spain, with 30,000 m³/day desalting capacity; Right:
RO-stacks and high pressure pumps of a 30,000 m³/day desalination plant in
Gran Canaria, Canary Islands. Source: Mertes, DME
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Power Plant Design Data ANDASOL 1 CSP/ROTurbine Type Superheated SuperheatedSteam Pressure to Turbine 100 bar 100 barSteam Temperature to Turbine 377 °C 377 °CBackup Concept HTF-Heater HTF-HeaterBackup Fuel Type Natural Gas Fuel OilCooling System evaporation seawaterGross Turbine Capacity 50 MW 16.5 MWEquivalent Annual Full Load Hours 3269 h/y 3269 h/yForecast Gross Electricity 163 GWh/y 54 GWh/yPeak Electric Efficiency 28 % 26 %Annual Electric Efficiency 15 % 15 %Expected Lifespan 40 years 40 yearsPlant Parasitics 14.0 GWh/y 4.6 GWh/y
Solar Field Design Data Parabolic Trough Technology SKAL-ET SKAL-ETAbsorber Tube PTR-70 PTR-70Heat Transfer Fluid Synthetic Oil Synthetic OilSolar Field Collector Area 510120 m² 168340 m²Number of Parabolic Mirrors 209664 mirrors 69189 mirrorsNumber of Receivers (@ 4 m length each) 22464 pipes 7413 pipesNumber of Solar Sensors 624 sensors 206 sensorsAnnual Direct Normal Irradiation (DNI) 2136 kWh/m²/y 2136 kWh/m²/yAnnual Solar Heat 545 GWh_th/y 180 GWh_th/ySolar Field Peak Efficiency 70 % 70 %Solar Field Annual Efficiency 50 % 50 %Land Use 2.00 km² 0.66 km²
Storage Design DataType: 2-Tank 2-TankStorage Fluid: Molten Salt Molten SaltCharging Capacity: 131 MW_th 43 MW_thDischarging Capacity: 119 MW_th 39 MW_thStorage Capacity in Heat Units: 1010 MWh_th 333 MWh_thStorage Capacity in Full Load Hours: 7.5 h 7.5 hStorage Tank Volume: 15870 m³ 5237 m³Storage Tank Height: 14 m height 8 m heightStorage Tank Diameter: 38 m diameter 23 m diameterCold Tank Temperature: 292 °C 292 °CHot Tank Temperature: 386 °C 386 °CMelting Point of Fluid: 223 °C 223 °CSalt Mass: 28500 tons 9405 tonsNaNO3 Share 60 % weight 60 % weightKNO3 Share 40 % weight 40 % weightFlow Rate: 953 kg/s 314 kg/sAnnual Storage Efficiency: 95 % 95 %
Figure 5-9: Design parameters of Andasol 1 (50 MW) vs. an equivalent smaller 16.5 MW plant for power and desalination of type CSP/RO.
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5.3.2 Case 2: Multi-Effect Desalination Using Heat & Power from a CSP Plant (CSP/MED)
An appropriate concept for such a plant must still be developed. A possible
configuration could use a linear Fresnel collector field directly generating saturated
steam at 270 °C, 55 bar. An intermediate heat transfer fluid and respective heat
exchangers are not required in that case. A saturated back-pressure steam turbine
would be used for power generation. Heat storage would consist of a concrete block
with a high temperature and a low temperature section. The high temperature section
would serve to store heat at around 270-250°C for saturated steam generation for
the turbine, while the low temperature section would serve to store heat at around
250-75 °C for low temperature steam generation for the MED plant.
During daytime, excess steam from the oversized solar field that is not required for
the turbine is used to heat up the concrete storage. While passing through the
storage, the saturated steam entering at 270°C is condensed in the hot section of the
storage. The condensate then enters the cold section of the storage and leaves
ideally at about 73°C. The pressure of the condensate is then reduced to the
backpressure of the steam turbine via a throttle valve. Then it is mixed with the
condensate from the MED header and returned to the solar field by the feed pump of
the power cycle.
3 ~
destillate
brine
seawater
G270°C55 bar
73 °C55 bar
73 °C0.35 bar
73 °C, 0.35 bar73°C, 60 bar
solarfield
concrete storage
3 ~3 ~
destillate
brine
seawater
GG270°C55 bar
73 °C55 bar
73 °C0.35 bar
73 °C, 0.35 bar73°C, 60 bar
solarfield
concrete storage
Figure 5-10: CSP/MED plant during daytime operation
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During night time, the solar field is by-passed and the condensate directly enters the
cold end of the hot section of the concrete storage. There, its temperature is
increased to the evaporation temperature – which will be lower than at daytime – of
about 250 °C at a pressure of 40 bar. During discharge, pressure may be reduced to
as low as 11 bar, 185°C. Passing through the hot section of the storage, the water
evaporates and is then used to drive the turbine. During night, only the amount of
electricity required for the parasitic power demand of the power block and the power
for the MED pumps will be produced. Therefore, the turbine will be operating in
partial load, thus not generating enough steam for the MED process. The difference
will be taken from condensate pumped through the low temperature storage section
and evaporating at backpressure level, which will be added to the steam from the
turbine. For reasons of security and control, this addition will take place through
intermediate heat exchangers between the power cycle and the desalination cycle
not displayed here for simplicity. After condensation in the MED header, the
condensate will be fed back to the high-temperature and to the low temperature
storage.
3 ~
destillate
brine
seawater
G
75 °C0.35 bar
73 °C0.35 bar
250°C, 40 bar185°C, 11 bar
73°C, 40 bar
73 °C, 0.35 bar
3 ~3 ~
destillate
brine
seawater
GG
75 °C0.35 bar
73 °C0.35 bar
250°C, 40 bar185°C, 11 bar
73°C, 40 bar
73 °C, 0.35 bar
Figure 5-11: CSP/MED plant during night time operation
A possible advantage of this configuration is the independent control of power
generation and seawater desalination, which allows for a certain load-following of the
power generator while maintaining constant desalination capacity. Another
advantage is the simplicity both of the components and of the configuration, which
may help to reduce costs of electricity and water. There also seem to be several
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options for heat integration and efficiency enhancement that still must be exploited.
This must still be confirmed by a more detailed plant design and by hourly time series
modelling of plant performance under the specific conditions for the sites under
consideration. A general advantage of this configuration is that the lower operation
temperature within the solar field will yield higher thermal collector efficiency. On the
other hand, the efficiency of power generation will be lower than in Case 1.
The following pictures give same examples of the equipment that may be used in this
configuration:
Figure 5-12: Linear Fresnel demonstration power plant at Puerto Errado (PE 1), Spain with 2
x 900 metre collector lines and 2 MW saturated steam turbine (NOVATEC)
Figure 5-13: Concrete storage without insulation for a maximum temperature of 400 °C
mounted at the DLR test site in Stuttgart (left) and pre-fabricated tube bundle
before adding concrete (right) (Züblin, DLR)
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Figure 5-14: Photograph showing a 20 MW steam turbine with gearbox (left), low pressure
steam flange (centre, top) and high pressure steam inlet (right, top), Dimensions
L=7m , W= 3m , H=3m. Generator will be connected on the left (Length 5 m).